There are many processes, referred to as primary, secondary or tertiary type processes, allowing to recover hydrocarbons in reservoirs.
The recovery is referred to as primary when the petroleum fluids are produced under the sole action of the energy present in-situ. This energy can result from the expansion of the fluids under pressure in the reservoir: expansion of the oil, saturated with gas or not, expansion of a gas cap above the oil reservoir, or an active water table. During this stage, if the pressure in the reservoir falls below the bubble point of the oil, the gas phase coming from the oil will contribute to increasing the recovery ratio. Natural drainage recovery scarcely exceeds 20% of the fluids initially in place for light oils and it is often below this value for heavy oil reservoirs.
Secondary recovery methods are used to prevent too great a pressure decrease in the reservoir. The principle of these methods consists in supplying the reservoir with an external energy. Fluids are therefore injected into the reservoir through one or more injection wells in order to displace the usable petroleum fluids (referred to as "oil" hereafter) towards production wells. Water is often used as the displacement fluid. Its efficiency is however limited. A large part of the oil remains in place notably because the viscosity thereof is often higher than that of water. Furthermore, the oil remains trapped in the pore contractions of the formation as a result of the great interfacial tension difference between the latter and the water. Finally, the rock mass is often heterogeneous. In this context, the water injected will flow through the most permeable zones to reach the producing wells without sweeping large oil zones. These phenomena induce a great recovery loss.
Pressurized gas can also be injected into a reservoir for secondary recovery, gas having the well-known property of displacing appreciable amounts of oil. However, if the formation is heterogeneous, the gas being much less viscous than the oil and the water in place, it will flow through the rock by following only some of the most permeable channels and will rapidly reach the producing wells without the expected displacement effect.
It is also well-known to combine water and gas injections according to a method referred to as WAG method (Water Alternate Gas). According to this method, water and gas are injected successively as long as the petroleum fluids are produced under economical conditions. The purpose of water slugs is to reduce the mobility of the gas and to widen the swept zone. Many improvements have been proposed for this technique: surfactants can be added to the water in order to decrease the water-oil interfacial tension, a foaming agent can be added to the water: the foam formed in the presence of the gas significantly reduces the mobility thereof. Such a method is for example described in U.S. Pat. No. 3,893,511. The applicant's patent FR-2,735,524 also describes an improved process consisting in adding an agent reducing the interfacial tension between the water and the gas to at least one of the water slugs alternately injected. Under the effect of this agent, alcohol for example, the oil cannot spread on the water film covering the rock mass. The oil remains in the form of droplets that slow the displacement of the gas down. The applicant's patent FR-2,764,632 describes a process comprising alternate injection of gas slugs and of water slugs wherein a pressurized gas soluble in both water and oil is added to at least one of the water slugs. The production stage comprises releasing the pressure prevailing in the reservoir so as to generate gas bubbles that drive the hydrocarbons out of the pores of the rock mass.
These secondary recovery techniques lead to recovery ratios of 25 to 50% of the oil initially in place.
The purpose of tertiary recovery is to improve this recovery ratio when the residual oil saturation is reached. This designation is applied to the injection, into a reservoir, of a miscible gas, of a microemulsion, of steam, or to in-situ combustion.
The definition of these primary, secondary and tertiary recovery techniques and their chronological application during production of a reservoir date from several years. Pressure maintenance techniques are currently used from the start of reservoir development and fluid injection techniques previously referred to as tertiary are carried out before a marked decline of the initial pressure of the reservoir.
More than 30% of the hydrocarbon fields produced contain acid compounds such as CO.sub.2 and H.sub.2 S. Development of these fields requires treating processes allowing the usable gases to be separated from the acid gases. The carbon dioxide coming from these plants is often discharged into the atmosphere, thus increasing the climate disturbances and the greenhouse effect. Hydrogen sulfide management is problematic because of the high toxicity of this gas. It is generally converted to solid sulfur by means of a Claus chain. This process requires a high investment on which a return is not secured in times where the world production of solid sulfur exceeds the needs. Reinjection of these acid gases in the reservoir after complete or partial solubilization in an aqueous phase, which can be all or part of the production water, fresh water or a brine from a groundwater table, sea water or others, affords two advantages: it allows to get rid of the acid gases at a low cost, without any polluting atmospheric discharge, and to increase the reservoir productivity.